EP2976499B1 - Systèmes et procédés d'optimisation de mesures de gradient dans des opérations de télémétrie - Google Patents

Systèmes et procédés d'optimisation de mesures de gradient dans des opérations de télémétrie Download PDF

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Publication number
EP2976499B1
EP2976499B1 EP13716095.8A EP13716095A EP2976499B1 EP 2976499 B1 EP2976499 B1 EP 2976499B1 EP 13716095 A EP13716095 A EP 13716095A EP 2976499 B1 EP2976499 B1 EP 2976499B1
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European Patent Office
Prior art keywords
sensor
blade
extension housing
pair
diameter
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German (de)
English (en)
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EP2976499A1 (fr
Inventor
Richard Thomas Hay
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Halliburton Energy Services Inc
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Halliburton Energy Services Inc
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    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B47/00—Survey of boreholes or wells
    • E21B47/02—Determining slope or direction
    • E21B47/022—Determining slope or direction of the borehole, e.g. using geomagnetism
    • E21B47/0228—Determining slope or direction of the borehole, e.g. using geomagnetism using electromagnetic energy or detectors therefor
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B17/00—Drilling rods or pipes; Flexible drill strings; Kellies; Drill collars; Sucker rods; Cables; Casings; Tubings
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B47/00—Survey of boreholes or wells
    • E21B47/01—Devices for supporting measuring instruments on drill bits, pipes, rods or wirelines; Protecting measuring instruments in boreholes against heat, shock, pressure or the like
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B47/00—Survey of boreholes or wells
    • E21B47/02—Determining slope or direction
    • E21B47/022—Determining slope or direction of the borehole, e.g. using geomagnetism

Definitions

  • the present disclosure relates generally to well drilling operations and, more particularly, to systems and methods for optimizing gradient measurements in ranging operations.
  • a target well In certain instances, such as in a blowout, it may be necessary to intersect a first well, called a target well, with a second well, called a relief well.
  • the second well may be drilled for the purpose of intersecting the target well, for example, to relieve pressure from the blowout well.
  • Contacting the target well with the relief well typically requires multiple downhole measurements to identify the precise location of the target well.
  • One such measurement is a gradient measurement that identifies changes in an electromagnetic field within the formation. The accuracy of the gradient measurements may depend on the distance between sensors measuring the electromagnetic field gradient. Unfortunately, most downhole drilling assemblies and operations provide little flexibility regarding the space between such sensors for the purpose of determining gradient.
  • US patent 5,343,152 discloses apparatus for making distance and direction measurements in a downhole measurement-while-drilling (MWD) system.
  • the apparatus comprises subsections or drill collars that are secured end-to-end to form a drill string and are lowered into the well so drilling progresses in conventional manner.
  • a pair of sensors for performing the required distance and direction measurements are located in the drill string near the bottom of the drill string, such as in the penultimate drill string collar or subsection.
  • a system for optimizing gradient measurements in ranging operations comprising: a drilling assembly comprising a drill string and a second portion, wherein the drill string has a first diameter and the second portion has a second diameter that is greater than the first diameter; a sensor pair disposed within the second portion and proximate to an outer radial surface of the second portion; and a processor in communication with the drilling assembly, wherein the processor is arranged to determine at least one electromagnetic field gradient measurement based, at least in part, on outputs of the sensor pair, wherein the second portion comprises a sensor extension housing, wherein the sensor extension housing comprises a first blade and a second blade, and wherein a first sensor of the sensor pair is disposed within the first blade and a second sensor of the sensor pair is disposed within the second blade.
  • a method for optimizing gradient measurements in ranging operations comprising: disposing a drilling apparatus within a borehole, wherein the drilling apparatus comprises a drill string and a second portion, and the drill string has a first diameter, and the second portion has a second diameter that is greater than the first diameter; receiving measurements from a sensor pair disposed within the second portion of the drilling apparatus and proximate to an outer radial surface of the second portion; and determining an electromagnetic field gradient measurement at a processor in communication with the drilling apparatus, wherein the gradient measurement is based, at least in part, on at least one output from the sensor pair, wherein the second portion comprises a sensor extension housing, wherein the sensor extension housing comprises a first blade and a second blade, and wherein a first sensor of the sensor pair is disposed within the first blade and a second sensor of the sensor pair is disposed within the second blade.
  • the present disclosure relates generally to well drilling operations and, more particularly, to systems and methods for optimizing gradient measurements in ranging operations.
  • Embodiments of the present disclosure may be applicable to drilling operations that include but are not limited to target (such as an adjacent well) following, target intersecting, target locating, well twinning such as in SAGD (steam assist gravity drainage) well structures, drilling relief wells for blowout wells, river crossings, construction tunneling, as well as horizontal, vertical, deviated, multilateral, u-tube connection, intersection, bypass (drill around a mid-depth stuck fish and back into the well below), or otherwise nonlinear wellbores in any type of subterranean formation.
  • target such as an adjacent well
  • target intersecting such as in SAGD (steam assist gravity drainage) well structures
  • drilling relief wells for blowout wells river crossings, construction tunneling, as well as horizontal, vertical, deviated, multilateral, u-tube connection, intersection, bypass (drill around a mid-depth stuck fish and back into the well below), or otherwise nonlinear wellbores in any type of subterranean formation.
  • SAGD steam assist gravity drainage
  • Embodiments may be applicable to injection wells, and production wells, including natural resource production wells such as hydrogen sulfide, hydrocarbons or geothermal wells; as well as borehole construction for river crossing tunneling and other such tunneling boreholes for near surface construction purposes or borehole u-tube pipelines used for the transportation of fluids such as hydrocarbons.
  • natural resource production wells such as hydrogen sulfide, hydrocarbons or geothermal wells
  • borehole construction for river crossing tunneling and other such tunneling boreholes for near surface construction purposes borehole u-tube pipelines used for the transportation of fluids such as hydrocarbons.
  • the system comprises a drilling apparatus comprising a drill string and a second portion.
  • the drill string may comprise a bottom hole assembly (BHA), and the second portion may comprise a sensor extension housing.
  • BHA bottom hole assembly
  • the drill string has a first diameter and the second portion has a second diameter that is greater than the first diameter.
  • the second portion may comprise a plurality of blades, and the diameter of the second portion may comprise the diameter of the sensor extension housing at the face of the blades, which may approach the diameter of the borehole.
  • the system also includes a sensor pair disposed within the second portion and proximate to an outer radial surface of the second portion.
  • the sensor pair may include but is not limited to an induction type sensor, a Hall Effect magnetometer sensor, a magnetic gradiometer or a combination or pair of any of the sensors listed above.
  • the outer radial surface of the second portion may comprise the faces the blades of the sensor extension housing.
  • the sensor pair may be divided between two blades, with each sensor of the sensor pair being disposed in a recessed portion and proximate to the face of a separate blade.
  • the separate blades may be diametrically opposite with respect to the longitudinal axis of the second portion, maximizing the radial distance between the sensor pair and increasing the accuracy of the gradient measurement, as will be described below.
  • a processor is in communication with the drilling apparatus, and in particular the sensor pair.
  • the processor determines at least one gradient measurement based, at least in part, on outputs of the sensor pair.
  • the accuracy and / or sensitivity may be increased by increasing the distance between the individual sensors of the sensor pair within the sensor extension housing in order to measure the maximum difference in the superimposed EM field over the earth's magnetic field.
  • the distance between the sensors in an x/y plane may be increased by positioning the sensors in a sensor extension housing with blades that generally approaches or is equal to the diameter of the borehole, while still allowing for junk slot space to permit cuttings and drilling mud to travel upwards in the annulus while drilling.
  • Fig. 1A shows an example drilling system 100, according to aspects of the present disclosure.
  • the drilling system 100 includes rig 101 at the surface 105 and positioned above borehole 106 within a subterranean formation 102.
  • Rig 101 may be coupled to a drilling assembly 107, comprising drill string 108 and bottom hole assembly (BHA) 109.
  • BHA 109 may comprise a drill bit 113, an MWD apparatus 111, and a sensor extension housing 110.
  • the sensor extension housing 110 may comprise at least one sensor pair 114.
  • the at least one sensor pair 114 may include but is not limited to an induction type sensor, a Hall effect magnetometer sensor, a magnetic gradiometer or a combination or pair of any of the magnetometers listed above.
  • the sensor extension housing 110 may be positioned at various locations within the BHA 109, or above the BHA 109, such as between the drill string 108 and the BHA 109. It may be advantageous to position the sensor extension housing 110 as close to the bottom of the hole as possible.
  • the at least one sensor pair 114 may be placed in the drill bit 113 rather than in a BHA sub somewhere above the drill bit 113.
  • the sensor extension housing 110 may comprise an outer radial surface.
  • the outer radial surface is defined by a plurality of blades, with the plurality of blades comprising two diametrically opposite pairs of blades.
  • the outer radial surface may be defined by the blades and may establish a diameter 116 of the sensor extension housing 110.
  • the diameter 116 of the sensor extension housing 110 may be characterized as the distance between the outer faces of a pair of diametrically opposite blades with respect to a longitudinal axis of the sensor extension housing 110.
  • the diameter 116 of the sensor extension housing 110 may approach the diameter of the borehole 106.
  • the drill string 108 or BHA 109 may comprise a first portion of the drilling apparatus 107
  • the sensor extension housing 110 may comprise a second portion of the drilling apparatus 107.
  • the first portion may have a first diameter 115
  • the second portion may have a second diameter 116 that is greater than the first diameter 115.
  • the first diameter 115 may comprise the diameter of the drill string 108 or BHA 119.
  • the first diameter 115 may be constant or vary if different types of MWD tools are used in the BHA 109. That said, the various diameters of the first portion may be less than the diameter 116 of the sensor extension housing 110.
  • Ranging measurements may require that a location of borehole 103 be identified.
  • the borehole 103 may comprise a target well containing or composed of an electrically conductive member such as casing, liner or a drill string or any portion thereof that has had a blowout or that needs to be intersected, followed or avoided.
  • the borehole 103 includes an electrically conductive casing 140.
  • Identifying the location of the target well 103 may comprise taking various measurements. These measurement may include measurements of imposed current flowing on the target well 103 by excitation methods such as wireline electrodes, BHA based electrodes, or excitation of the target well casing 150 directly. These measurements may comprise various measurements of electromagnetic fields in the formation, such the gradient in the electromagnetic field. Gradient measurements or absolute magnetic field measurements may identify the distance and direction to the target well 103, which is useful for determining the location of the target well 103.
  • Drilling assembly 107 may include a gap sub 112 that may allows for the creation of a dipole electric field to be created across the gap to aid in flowing current off of the drill string and into the formation 102.
  • a time-varying current 134 may be induced within the formation 102 by energizing the portion of the drilling assembly 107 above the gap sub 112. Due to the higher conductivity of the casing 140 in the target well 103 that the surrounding formation 103, part of the induced current 134 may be concentrated at the casing 140 within the target well 103, and the current 138 on the casing 140 may induce an electromagnetic field (EM) 136 field in radial direction from the direction of the flow of the electric current 138.
  • EM electromagnetic field
  • the remaining induced current 134 may be received at the portion of the drilling assembly 107 below the gap sub 112.
  • the use of a time-varying current 134 may be useful to aid in detection of the induced EM field 136 by allowing the EM field 136 to be detected above the background magnetic field of the earth.
  • the time-varying current 134 may take a variety of forms, including sinusoidal, square wave, saw wave, etc.
  • the at least one sensor pair 114 may be disposed within sensor extension housing 110 and proximate to the outer radial surface of the sensor extension housing 110.
  • a sensor pair for gradient measurements may be aligned in a flat plane, with the accuracy of the gradient measurement depending on the distance between the sensors in the plane.
  • the sensor pair 114 may take independent measurements of the EM field 136, which can be used together to determine a gradient value of the EM field 116, as will be described below.
  • positioning the sensor pairs 114 in the blades of sensor extension housing 110 may allow for an increase in the distance between the sensor pair in an x/y plane that is perpendicular to the longitudinal axis of the sensor extension housing 110, which may increase the accuracy of the gradient value.
  • the distance between the sensor pairs 114 may be maximized to the extent allowed within the borehole 106.
  • the drilling assembly 107 may be in communication with a control unit 104 positioned at the surface 105.
  • the control unit 104 may comprise a processor and a memory device coupled to the process that may cause the processor to control the operation of the drilling assembly 107, receive outputs from the sensor pairs 114 and other measurement equipment, and determine certain measurement values, such as a gradient value, based at least in part on the output of the sensor pairs 114 and other measurement equipment.
  • certain processing, memory, and control elements may be positioned within the drilling assembly 107.
  • the sensor pairs 114 may be in communication with a steering control system, which may incorporate all or elements of control unit 104.
  • a steering control system may comprise an automatic steering control system located either within the drilling assembly 107 or at the surface 104.
  • the steering control assembly may receive measurements from the sensor pairs 114, determine a gradient value, and then automatically adjust the drilling direction of the drilling assembly to intersect, follow, or avoid the target well 103, depending on the operational requirements.
  • the steering control system may be at least partially controlled by a worker positioned at the surface. In such instances, the sensor pairs 114 may still communicate with a control unit 104 at the surface, which may determine a gradient value of the EM field 136, but the drilling direction may be manually controlled.
  • Fig. 1B shows an example drilling system 150, according to aspects of the present disclosure.
  • Fig. 1B illustrates a drilling system 150 using a sensor extension housing 154 and at least one sensor pair 156, similar to the corresponding elements in Fig. 1A .
  • the drilling system 150 comprises a different excitation scheme, however, that is equally applicable to the sensor extension housings described herein.
  • the excitation scheme may comprise a wireline 158 disposed in a borehole 160.
  • the wireline may comprise an insulated portion 158a and an uninsulated portion 158b.
  • the uninsulated portion 158b may be positioned between two gap subs 162a and 162b within the drilling assembly 152.
  • Time-varying current 164 may be injected by the wireline 158 into the formation 166, where it is received on the casing 168 within target well 170.
  • the current on the casing 168 may induce an EM field 172 in the formation, whose gradient may be measured with the sensor pairs 156 in the sensor extension housing 154.
  • the current 172 may be returned using an electrode 174 positioned at the surface.
  • Fig. 2 illustrates an example second portion of a drilling assembly, sensor extension housing 200.
  • the sensor extension housing 200 may be coupled to a first portion, such as drill string segments or a BHA, via threaded connections 212 and 213.
  • the sensor extension housing 200 may further be incorporated into a BHA using the threaded connections.
  • the sensor extension housing 200 may comprise a plurality of blades, including blades 201 and 202. As can be seen, blades 201 and 202 may be diametrically opposite relative to the longitudinal axis 280 of the sensor extension housing 200.
  • a sensor pair including sensors 205 and 206 may be at least partially disposed within the blades 201 and 202, respectively, proximate to outer radial surfaces of the sensor extension housing 200.
  • the outer radial surfaces of the sensor extension housing may comprise faces 216 and 217 of blades 201 and 202.
  • An outer radial surface of the sensor extension housing 200 may refer collectively to the faces of all of the blades of the sensor extension housing 200, or may refer to separate faces of particular blades individually.
  • the plurality of blades may be concentric in diameter, and the radial position of the sensors may be identical to aid in calibration of the system.
  • the actual offset from the longitudinal axis of any sensor pair does not have to be equal so long as the separation is accounted for, as will be described below.
  • the shape of the sensor extension housing can be eccentric in nature such as the blades on an eccentric drill bit.
  • the sensor pair 205 and 206 may be at least partially disposed within recessed areas 214 and 215 of the respective blades. Additionally, circuit boards 207 and 208 may also be disposed within the recessed areas 214 and 215, and may provide power to and a communication pathway to/from sensor pair 205 and 206 via wires 209, 210, and 211. Faces 216 and 217 may comprise detachable covers 203 and 204, respectively, which may at least partially cover recessed areas 214 and 215.
  • the sensor pair 205 and 206 may comprise induction type sensors with a ferromagnetic core such as mu-metal (laminated sheets or solid), iron (laminated sheets or solid), or a ferrite core, all of which may be wound with wire. In other embodiments, the sensors may comprise Hall Effect sensors or forms of magnetometers. Sensor pair 205 and 206 may at least partially protrude through the detachable covers 203 and 204, exposing the cores to the surrounding EM field.
  • a gravity sensor such as an accelerometer 250 may be included in the sensor package so that the orientation of the sensors 205 and 206 relative to the down direction can be determined and referenced back to the reference well geometry through the use of well-known survey calculation such as inclination and high side reference of the hole.
  • Gravity sensor arrangements can have several variations such as 2 orthogonal cross axis accelerometers or 3 orthogonal accelerometers with X and Y being the cross axis directions and the Z axis along the tool long axis in the hole.
  • the detachable covers 203 and 204 may be at least partially composed of a high magnetic-permeability material, such as a steel-alloy, mu metal, etc. This material may allow the magnetic flux to be drawn in through the detachable covers 203 and 204 and collected at the sensors 205 and 206.
  • the detachable covers 203 and 204 may be totally composed of high magnetic-permeability material, such as a steel alloy or a mu metal.
  • the blades may be fitted with highly magnetically permeable material such as steel, to aid in magnetic flux collection along this direction.
  • the entire sensor extension housing 200 may be made of the a non-magnetic alloy such as monel or Austenic stainless steel, having a very low magnetic relative permeability of 1.02 or less, to avoid shielding of the magnetic field emanating from the target excitation current.
  • a non-magnetic alloy such as monel or Austenic stainless steel, having a very low magnetic relative permeability of 1.02 or less, to avoid shielding of the magnetic field emanating from the target excitation current.
  • Fig. 3 illustrates a cross section of a sensor extension housing 300 with a similar configuration to sensor extension housing 200.
  • the sensor extension housing 300 comprises four blades 301-304.
  • the sensor extension housing 300 has four blades, other configurations are possible, including, but not limited to, different numbers of blades and blade with different configurations, such as spiraled.
  • each of the blades 301-304 may have corresponding sensors 313-316 disposed in recessed areas 305-308 that are at least partially covered by detachable covers 309-312. At least one of the blades may inclde an accelerometer 380.
  • the sensors pairs may comprise sensors 314 and 316 and sensors 313 and 315, which are diametrically opposite to increase the distance between them.
  • the sensor extension housing 300 may have a diameter D, which may be characterized by the distance between outer radial surfaces of diametrically opposite blades 302 and 304. Additionally, each one of the EM field sensors 313-316 may have a respective longitudinal axis 352-358. In the embodiment shown, the longitudinal axes 352-358 may be perpendicular to the longitudinal axis 350 of sensor extension housing 300.
  • the sensor pairs may be arranged in a flat x/y plane that is perpendicular to the longitudinal axis 350 of the sensor extension housing 300.
  • the accuracy of the gradient measurement may be affected by the distance between two sensors in a sensor pair, including the distance between sensors 313 and 315, and the distance between sensors 314 and 316.
  • sensor pairs may be arranged in the same cross axis plane, as in Fig. 3 , some axial separation is possible.
  • the axial displacement of a sensor pair can present problems with the gradient measurement if the angle of approach to the target well is not near enough.
  • the distance between two sensors in a sensor pair in the x/y plane may be increased to the limits of a corresponding borehole, thereby maximizing the gradient accuracy.
  • the sensor pair 313 and 315 is positioned proximate to an outer radial surface of the sensor extension housing 300, within blades 301 and 303, the distance between two sensors in the sensor pair along the x-axis is maximized.
  • the sensor pair 314 and 316 is positioned proximate to an outer radial surface of the sensor extension housing 300, within blades 302 and 304, the distance between the two sensors in the sensor pair along the y-axis is maximized.
  • sensor extension housing 400 may include a four-blade configuration similar to the sensor extension housings described above.
  • the sensor extension housing may comprise at least one sensor pair 401 and 404.
  • the sensor 401 may be disposed within a recessed portion 402 of blade 403.
  • the core 405 of the induction sensor 401 has been elongated, which may increase the amount of the magnetic flux collected by the sensor.
  • core of the sensor 401 may be extended along the same axis as the mated sensor 404 on the diametrically opposite side of the sensor extension housing 400.
  • an induction type sensor 501 may be turned 90° relative to the configuration in Fig. 4 , such that the longitudinal axis of the sensor 501 does not intersect with the longitudinal axis 550 of the sensor extension housing 500.
  • the sensor 501 may still be at least partially disposed within a recessed portion 502 of blade 504, such that it is proximate to the outer surface of the blade 504.
  • the sensor 501 may still form a sensor pair with sensor 505, and may include an electronics package 503.
  • Figs. 6A and 6B illustrate another example embodiment of sensor extension housing 600.
  • the sensor extension housing 600 may comprise an outer radial surface that is defined by a plurality of blades.
  • the outer radial surface comprises a diameter ⁇ D, which comprises the distance between the outer faces to two diametrically opposite blades, and is equally applicable to each pair of diametrically opposite blades.
  • At least one sensor pair may be positioned within the sensor extension housing 600.
  • the sensor extension housing 600 comprises eight separate sensors x1, x2, y1, y2, xy1, xy2, xy3, and xy4, positioned one in each of the eight blades, creating four sensor pairs.
  • the sensor pairs may comprise x1 and x2, y1 and y2, xy1 and xy2, and xy3 and xy4. As can be seen, the distance between each of the sensor pairs may be ⁇ D, given their positioning on diametrically opposite blades.
  • the final gradient measurement may comprise some averaging calculation of the individual gradient values.
  • the formulae described above are equally applicable when the distances between the various sensor pairs are not all equal. Specifically, provided the distance between two sensors in a sensor pair are known, the ⁇ D can be changed to determine the corresponding gradient value.
  • a control unit or computing element may be coupled to the sensor pairs, and may contain a processor and a memory device.
  • the memory device may contain a set of instruction that when executed by the memory device cause the processor to receive measurements from each of the sensor pair, and determine a gradient value.
  • the instruction may cause the processor to process the measurements using the equations above, or equations similar to those above.
  • the memory device may include stored data, such as the distance between the sensors of each sensor pair, that can be used to determine gradient measurements.
  • the gradient measurements may identify the location of a target within a formation.
  • the control unit or computing unit may transmit the gradient measurement to steering control assembly, which may automatically adjust a drilling direction of a drilling assembly to intersect, follow, or avoid the target.
  • Fig. 7 illustrates an another sensor extension housing 700, according to aspects of the present disclosure.
  • the sensor extension housing 700 may have an outer radial surface 702 that is defined by a ring surface rather than the exterior surface of blades.
  • the sensor extension housing 700 may comprise a plurality of wedges 703a-d (703d not shown) within the outer radial surface in which the sensors 706 may be disposed.
  • the sensor extension housing 700 may also comprise at least one sensor pair, and still provide junk slots 704 through which upward flowing drilling fluid may pass.

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Claims (11)

  1. Système pour optimiser des mesures de gradient dans des opérations de télémétrie, comprenant :
    un ensemble de forage (107) comprenant un train de tiges de forage (108) et une seconde portion (110), dans lequel le train de tiges de forage a un premier diamètre (115) et la seconde portion a un second diamètre (116) qui est supérieur au premier diamètre,
    une paire de capteurs (114) disposés dans la seconde portion (110) et à proximité d'une surface radiale extérieure de la seconde portion ; et
    un processeur (104) en communication avec l'ensemble de forage (107), dans lequel le processeur est agencé pour déterminer au moins une mesure de gradient de champ électromagnétique sur la base, au moins en partie, de sorties de la paire de capteurs,
    dans lequel la seconde portion comprend un boîtier d'extension de capteur (110),
    dans lequel le boîtier d'extension de capteur (200) comprend une première aube (201) et une seconde aube (202), et
    dans lequel un premier capteur (205) de la paire de capteurs est disposé dans la première aube (201) et un second capteur (206) de la paire de capteurs est disposé dans la seconde aube (202).
  2. Système selon la revendication 1, dans lequel la première aube (201) et la seconde aube (202) sont diamétralement opposées par rapport à un axe longitudinal du boîtier d'extension de capteur (200).
  3. Système selon la revendication 2, dans lequel une face (216) de la première aube (201) comprend un couvercle détachable (203).
  4. Système selon la revendication 3, dans lequel le couvercle détachable (203) est au moins partiellement composé d'un métal-mu.
  5. Système selon l'une quelconque des revendications précédentes, dans lequel la paire de capteurs comprend une combinaison d'un capteur de type induction, d'un capteur de magnétomètre à effet Hall, et un gradiomètre magnétique.
  6. Procédé pour optimiser des mesures de gradient dans des opérations de télémétrie, comprenant :
    la disposition d'un appareil de forage dans un trou de forage, dans lequel
    l'appareil de forage comprend un train de tiges de forage (108) et une seconde portion (110), et
    le train de tiges de forage a un premier diamètre (115), et la seconde portion a un second diamètre (116) qui est supérieur au premier diamètre ;
    la réception de mesures en provenance d'une paire de capteurs (114) disposés dans la seconde portion (110) de l'appareil de forage et à proximité d'une surface radiale extérieure de la seconde portion ; et
    la détermination d'une mesure de gradient de champ électromagnétique au niveau d'un processeur (104) en communication avec l'appareil de forage, dans lequel la mesure de gradient est basée, au moins en partie, sur au moins une sortie de la paire de capteurs,
    dans lequel la seconde portion comprend un boîtier d'extension de capteur (110),
    dans lequel le boîtier d'extension de capteur (200) comprend une première aube (201) et une seconde aube (202), et
    dans lequel un premier capteur (205) de la paire de capteurs est disposé dans la première aube (201) et un second capteur (206) de la paire de capteurs est disposé dans la seconde aube (202).
  7. Procédé selon la revendication 6, dans lequel la première aube (201) et la seconde aube (202) sont diamétralement opposées par rapport à un axe longitudinal du boîtier d'extension de capteur (200).
  8. Procédé selon la revendication 6 ou 7, dans lequel une face (216) de la première aube (201) comprend un couvercle détachable (203).
  9. Procédé selon la revendication 8, dans lequel le couvercle détachable (203) est au moins partiellement composé d'un métal-mu.
  10. Procédé selon la revendication 6, 7 ou 8, dans lequel la paire de capteurs comprend une combinaison d'un capteur de type induction, d'un capteur de magnétomètre à effet Hall, et un gradiomètre magnétique.
  11. Procédé selon la revendication 10, dans lequel la seconde portion (110) se compose d'un alliage de feuille non magnétique.
EP13716095.8A 2013-03-18 2013-03-18 Systèmes et procédés d'optimisation de mesures de gradient dans des opérations de télémétrie Active EP2976499B1 (fr)

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CA2900462A1 (fr) 2014-09-25
MX360280B (es) 2018-10-26
BR112015019236A2 (pt) 2017-07-18
CA2900462C (fr) 2017-10-24
MX2015010535A (es) 2016-03-04
CN105229260A (zh) 2016-01-06
BR112015019236B1 (pt) 2021-06-08
AU2013383424A1 (en) 2015-07-30
US20160003029A1 (en) 2016-01-07
RU2015134588A (ru) 2017-04-24
EP2976499A1 (fr) 2016-01-27
AU2013383424B2 (en) 2016-07-21
US9951604B2 (en) 2018-04-24
WO2014149030A1 (fr) 2014-09-25

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